1. Field of the Invention
The present invention relates generally to controlling fluid loss to a formation and diverting treatments for stimulating, selectively stimulating, or selectively de-stimulating a well.
2. Background Art
When drilling or completing wells in earth formations, various fluids typically are used in the well for a variety of reasons. For the purposes herein, these fluids will be generically referred to as “well fluids.” Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroliferous formation), transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, minimizing fluid loss into the formation after the well has been drilled and during completion operations such as, for example, perforating the well, replacing a tool, attaching a screen to the end of the production tubulars, gravel-packing the well, or fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, emplacing a packer and packer fluid, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
Brines (such as, for example, aqueous CaBr2) commonly are used as well fluids because of their wide density range and the fact that brines are typically substantially free of suspended solids. In addition, brines are often used in order to achieve a suitable density for use in well-drilling operations. Typically, brines comprise halide salts of mono- or divalent cations, such as sodium, potassium, calcium, and zinc. Chloride-based brines of this type have been used in the petroleum industry for over 50 years; bromide-based brines, for at least 25 years; and formate-based brines, for roughly the past ten years. One additional advantage of using brines is that brines typically do not damage certain types of downhole formations; and for formations that are found to interact adversely with one type of brine, often there is another type of brine available with which that formation will not interact adversely.
A variety of compounds are typically added to brine-based well fluids. For example, a brine-based well fluid may also include viscosifiers, corrosion inhibitors, lubricants, pH control additives, surfactants, solvents, and/or weighting agents, among other additives. Some typical brine-based well fluid viscosifying additives include natural polymers and derivatives thereof such as xanthan gum and hydroxyethyl cellulose (HEC). In addition, a wide variety of polysaccharides and polysaccharide derivatives may be used, as is well known in the art.
Some synthetic polymer and oligomer additives such as poly(ethylene glycol) [PEG], poly(diallyl amine), poly(acrylamide), poly(aminomethylpropylsulfonate) [AMPS polymer], poly(acrylonitrile), poly(vinyl acetate) [PVA], poly(vinyl alcohol) [PVOH], polyvinyl amine), poly(vinyl sulfonate), poly(styryl sulfonate), poly(acrylate), poly(methyl acrylate), poly(methacrylate), poly(methyl methacrylate), poly(vinylpyrrolidone), poly(vinyl lactam), and co-, ter-, and quater-polymers of the following co-monomers: ethylene, butadiene, isoprene, styrene, divinylbenzene, divinyl amine, 1,4-pentadiene-3-one (divinyl ketone), 1,6-heptadiene-4-one (diallyl ketone), diallyl amine, ethylene glycol, acrylamide, AMPS, acrylonitrile, vinyl acetate, vinyl alcohol, vinyl amine, vinyl sulfonate, styryl sulfonate, acrylate, methyl acrylate, methacrylate, methyl methacrylate, vinylpyrrolidone, and vinyl lactam are also often used as viscosifiers.
One example of how a brine-based well fluid may be used in combination with the above listed polymers and oligomers is set forth below. When drilling progresses to the depth of penetrating a hydrocarbon bearing formation, special care may be required to maintain the stability of the wellbore. Examples of formations in which stability problems often arise include highly permeable and/or poorly consolidated formations. In these types of formations, a drilling technique known as “under-reaming” may be used. In under-reaming, the wellbore is drilled to penetrate the hydrocarbon bearing zone using conventional techniques. A casing generally is set in the wellbore to a point just above the hydrocarbon bearing zone. The hydrocarbon bearing zone then may be re-drilled, for example, using an expandable under-reamer that increases the diameter of the already-drilled wellbore below the casing.
Under-reaming is usually performed using special “clean” drilling fluids. Typical drilling fluids used in under-reaming are expensive, aqueous, dense brines that are viscosified with a gelling and/or crosslinked polymer to aid in the removal of formation cuttings. The high permeability of the target formation, however, may allow large quantities of the drilling fluid to be lost into the formation. Once the drilling fluid is lost into the formation, it becomes difficult to remove. Calcium and zinc bromide brines can form highly stable, acid insoluble compounds when reacted with the formation or substances contained therein. This reaction may reduce the permeability of the formation to any subsequent out-flow of targeted hydrocarbons. One of the most effective ways to prevent such damage to the formation is to limit fluid loss into the formation.
For a drilling fluid to perform these functions and allow drilling to continue, the drilling fluid must stay in the borehole. Frequently, undesirable formation conditions are encountered in which substantial amounts or, in some cases, practically all of the drilling fluid may be lost to the formation. Drilling fluid can leave the borehole through large or small fissures or fractures in the formation or through a highly porous rock matrix surrounding the borehole.
Most wells are drilled with the intent of forming a filter cake of varying thickness on the sides of the borehole. The primary purpose of the filter cake is to reduce the large losses of drilling fluid to the surrounding formation. Unfortunately, formation conditions are frequently encountered which may result in unacceptable losses of drilling fluid to the surrounding formation despite the type of drilling fluid employed and filter cake created.
Providing effective fluid loss control without damaging formation permeability in completion operations has been a prime requirement for an ideal fluid loss-control pill. Conventional fluid loss control pills include oil-soluble resins, calcium carbonate, and graded salt fluid loss additives, which have been used with varying degrees of fluid loss control. These pills achieve their fluid loss control from the presence of solvent-specific solids that rely on filter-cake build up on the face of the formation to inhibit flow into and through the formation. However, these additive materials can cause severe damage to near-wellbore areas after their application. This damage can significantly reduce production levels if the formation permeability is not restored to its original level. Further, at a suitable point in the completion operation, the filter cake must be removed to restore the formation's permeability, preferably to its original level.
A major disadvantage of using these conventional fluid loss additives is the long periods of clean-up required after their use. Fluid circulation, which in some cases may not be achieved, is often required to provide a high driving force, which allows diffusion to take place to help dissolve the concentrated build up of materials. Graded salt particulates can be removed by circulating unsaturated salt brine to dissolve the particles. In the case of a gravel pack operation, if this occurs before gravel packing, the circulating fluid often causes sloughing of the formation into the wellbore and yet further loss of fluids to the formation.
If removal is attempted after the gravel pack, the gravel packing material often traps the particles against the formation and makes removal much more difficult. Other particulates, such as the carbonates can be removed with circulation of acid, however, the same problems may arise. Oil-soluble resins, carbonate, and graded salt particulate will remain isolated in the pores of the formation unless they are in contact with solvent. In the cases where the solid materials cover a long section of wellbore, the rapid dissolution by solvent causes localized removal, Consequently, a thief zone forms and the majority of the solvent leaks through the thief zone instead of spreading over the entire wellbore length.
Additionally, in stimulation treatments, such as acidization, hydraulic fracturing, etc., it is often desirable to plug a more permeable area of the formation to divert treatment fluids to less permeable areas receiving inadequate treatment. Well treatments, such as acid and fracture treatments of subterranean formations are routinely used to improve or stimulate the recovery of hydrocarbons. In many cases, a subterranean formation may include two or more intervals having varying permeability and/or injectivity. Some intervals may possess relatively low injectivity, or ability to accept injected fluids, due to relatively low permeability, high in-situ stress, and/or formation damage. Such intervals may be completed through perforations in a cased wellbore and/or may be completed open hole. In some cases, such formation intervals may be present in a highly deviated or horizontal section of a wellbore, for example, a lateral open hole section. In any case, when treating multiple intervals having variable injectivity it is often the case that most, if not all, of the introduced well treatment fluid will be displaced into one, or only a few, of the intervals having the highest injectivity.
In an effort to more evenly distribute displaced well treatment fluids into each of the multiple intervals being treated, methods and materials for diverting treatment fluids into intervals of lower permeability and/or injectivity have been developed. However, conventional diversion techniques may be costly and/or may achieve only limited success. In this regard, mechanical diversion techniques are typically complicated and costly. Furthermore, mechanical diversion methods are typically limited to cased hole environments and depend upon adequate cement and tool isolation for achieving diversion.
Alternatively, diversion agents such as polymers, suspended solid materials and/or foam have been employed when simultaneously treating multiple intervals of variable injectivity. Such diversion agents are typically pumped into a subterranean formation prior to a well treatment fluid in order to seal off intervals of higher permeability and divert the well treatment fluid to intervals of lower permeability. However, the diverting action of such diversion agents is often difficult to predict and monitor, and may not be successful in diverting treatment fluid into all desired intervals. Additionally, while it is desirable for these viscous gels to be stable at the bottomhole temperature, it is also desirable that they be removable from the formation rapidly after the treatment in order to eliminate any potential damage to the high permeability intervals.
Oil-soluble resins have previously been used as a diverting treatment. These resins, however, only dissolve when contacted by oil. If used in a water-wet environment, the oil-soluble resins generally present difficulties in breaking the plug of resin to allow for removal from the formation.
The use of water-soluble polymers coupled with proper concentration of cross-linker(s) as diverting agents has become a common practice in recent years for oil recovery applications. In such practice a solution containing the polymer and cross-linker(s), referred to as gelant, is injected in desired zones and allowed sufficient time to set into a solid or semi-solid gel. These gels are used in injection wells to divert the flow of injected water or gas (CO2) to un-swept zones where additional oil can be recovered. Cross-linked polymer gel may have more use in a more permanent application as practical breaker systems are not always effective in removing the gelled plug. Typically, oxidizing agents at low pH have the most success in breaking the cross-linked polymer gel; however, these breaker systems are hard on the metallurgy as they tend to be fairly corrosive.
Accordingly, there exists a need for a stable fluid loss treatment that may be easily emplaced in the well and removed with ease without causing damage downhole.